SEALING ELEMENT OF ISOLATION DEVICE WITH INNER CORE AND OUTER SHELL

Abstract

A treatment operation can be performed in a wellbore. A zonal isolation device, such as a frac plug, can be set within a tubing string in the wellbore to isolate one zone from another zone. The plug can include a slip system and a sealing element located circumferentially around an inner mandrel of the plug. The sealing element can include an outer shell that surrounds an inner core. The outer shell can be made from a material having a high Young's modulus, while the inner core can have a very low Young's modulus. The outer shell can prevent premature deformation and expansion of the sealing element during run in. The outer shell and inner core can wholly or partially disintegrate in a desired a period of time after setting of the plug in the tubing string.

Description

TECHNICAL FIELD

An isolation device and methods of using the isolation device are provided. The isolation device includes a sealing element that includes a solid core and a shell surrounding the core. The core and the shell can be made from different materials.

BRIEF DESCRIPTION OF THE FIGURES

The features and advantages of certain embodiments will be more readily appreciated when considered in conjunction with the accompanying figures. The figures are not to be construed as limiting any of the preferred embodiments.

FIG. 1 is a perspective view of an isolation device in a run-in state.

FIG. 2 is a cross-sectional view of the isolation device of FIG. 1.

FIG. 3 is a cross-sectional view of the isolation device of FIG. 1 after being set within a tubing string.

FIG. 4 is a cross-sectional view of the sealing element of the isolation device according to certain embodiments.

DETAILED DESCRIPTION OF THE INVENTION

Oil and gas hydrocarbons are naturally occurring in some subterranean formations. In the oil and gas industry, a subterranean formation containing oil and/or gas is referred to as a reservoir. A reservoir can be located under land or offshore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a wellbore is drilled into a reservoir or adjacent to a reservoir. The oil, gas, or water produced from a reservoir is called a reservoir fluid.

As used herein, a “fluid” is a substance having a continuous phase that can flow and conform to the outline of its container when the substance is tested at a temperature of 71° F. (22° C.) and a pressure of one atmosphere “atm” (0.1 megapascals “MPa”). A fluid can be a liquid or gas. A homogenous fluid has only one phase, whereas a heterogeneous fluid has more than one distinct phase.

A well can include, without limitation, an oil, gas, or water production well, an injection well, or a geothermal well. As used herein, a “well” includes at least one wellbore. A wellbore can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched. As used herein, the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, a “well” also includes the near-wellbore region. The near-wellbore region is generally considered to be the region within approximately 100 feet radially of the wellbore. As used herein, “into a subterranean formation” means and includes into any portion of the well, including into the wellbore, into the near-wellbore region via the wellbore, or into the subterranean formation via the wellbore.

A portion of a wellbore can be an open hole or a cased hole. In an open-hole wellbore portion, a tubing string can be placed into the wellbore. The tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore. In a cased-hole wellbore portion, a casing is placed into the wellbore that can also contain a tubing string. A wellbore can contain an annulus. Examples of an annulus include but are not limited to the space between the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a casing and the outside of a tubing string in a cased-hole wellbore.

It is not uncommon for a wellbore to extend several hundreds of feet or several thousands of feet into a subterranean formation. The subterranean formation can have different zones. A zone is an interval of rock differentiated from surrounding rocks on the basis of its fossil content or other features, such as faults or fractures. For example, one zone can have a higher permeability compared to another zone. It is often desirable to treat one or more locations within multiples zones of a formation. One or more zones of the formation can be isolated within the wellbore via the use of an isolation device to create multiple wellbore intervals. At least one wellbore interval corresponds to a formation zone. The isolation device can be used for zonal isolation and functions to block fluid flow within a tubular section, such as a tubing string, or within an annulus. The blockage of fluid flow prevents the fluid from flowing across the isolation device in any direction and isolates the zone of interest. In this manner, treatment techniques, such as fracturing operations, can be performed within the zone of interest.

Common isolation devices include, but are not limited to, a ball and a seat, a bridge plug, a packer, a plug, a frac plug, and a wiper plug. Plugs, for example, frac plugs, are generally composed primarily of slips, wedges, an inner plug mandrel, a spacer ring, a mule shoe, and a rubber sealing element. The plug can also include a setting device and an additional mandrel, such as a tension mandrel or setting mandrel. The plug can be introduced into the wellbore and positioned at a desired location within a tubing string. The “tubing string” can also be a casing. The plug can be set after being placed at the desired location. As used herein, the term “set” and all grammatical variations means one or more components of the plug are actuated to keep the plug at the desired location and substantially diminish or restrict fluid flow past the outside of the plug. For example, the spacer ring can be mechanically actuated to move a top slip into engagement with the inner diameter (I.D.) of the tubing string. A mule shoe, which is typically pinned and/or threaded to the inner plug mandrel, can also be mechanically actuated to move a bottom slip into engagement with the I.D. of the tubing string. Movement of the top and bottom slips can cause top and bottom wedges to mechanically actuate the rubber sealing element to radially expand away from the inner mandrel and engage with the I.D. of the tubing string. The rubber sealing element can also expand inwardly and engage with the outer diameter of the inner plug mandrel. This expansion of the rubber sealing element creates zonal isolation by substantially diminishing or restricting fluid flow around the outside of the plug. A ball can then be seated onto the plug whereby after being seated, the ball restricts fluid flow through the inner plug mandrel.

One significant disadvantage to traditional plugs is that premature extrusion and setting can occur during run-in of the plug. Common sealing elements utilize elastomers, such as nitrile butadiene rubber or thermoset polyurethanes, that have a sufficient elastic modulus such that the sealing element can expand and engage with the I.D. of the tubing string after setting. However, during the run-in of the plug, fluid flow around the outside of the plug can increase such that the elastomeric sealing element is pulled out away from the inner mandrel and into a flow stream by the force of the fluid. The fluid flow stream can then exert a downward force on the portion of the sealing element that was pulled out into the flow stream, which can cause the sealing element to engage with the I.D. of the tubing string and prematurely cause the plug to lodge and set within the tubing at an undesired location. Accordingly, the pump down bypass rating can be limited by the geometry of the plug.

Isolation devices can be classified as permanent, retrievable, or drillable. While permanent isolation devices, such as packers, are generally designed to remain in the wellbore after use, retrievable devices are designed to be removed after use, and drillable devices are designed to be drilled or milled after use. Removal of an isolation device from the wellbore can be accomplished by milling or drilling at least a portion of the device or the entire device. Another disadvantage to traditional elastomeric sealing elements is an increased risk of clogging the drilling or milling bit during removal due to the elastomeric sealing element forming large pieces or chunks during removal. Some sealing elements are designed to dissolve or degrade after use. These sealing elements can include an elastomeric material with one or more additives that control the properties of the sealing element, such as the onset time of degradation, the degradation rate, or hardness. However, one significant disadvantage to degradable or dissolvable sealing elements is that additives most commonly negatively affect the hardness and elastic modulus of the sealing element. As such, there is a need and ongoing industry concern for improved plugs that overcome the aforementioned problems.

Hardness is the ability of a material to resist localized deformation, for example by measuring the surface of the material's resistance to indentation. A material with a higher hardness will have less surface deformation than another material with a lower hardness. Elastic modulus is a property that describes a material's stiffness and is therefore one of the most important properties of solid materials. Elastic modulus, also known as modulus of elasticity, is the unit of measurement of a material's resistance to being deformed elastically (i.e., non-permanently) when a stress is applied to it. The elastic modulus of an object is defined as the slope of its stress—strain curve in the elastic deformation region. Stress is defined as the force per unit area, and strain is defined as the elongation or contraction per unit length. Elastic modulus may be thought of as a material's resistance to elastic deformation. A stiffer material has a higher elastic modulus than a more flexible material.

Novel plugs are disclosed. The plug can include a sealing element that includes an inner core and an outer shell that surrounds the inner core. The outer shell and inner core can be made from different materials. The outer shell can be made from a material that has a lower elastic modulus, and therefore, is prevented from prematurely extruding or deforming away from the inner mandrel during run in and prematurely setting within the tubing string. The plug can be used for zonal isolation to treat a zone of interest within a subterranean formation. The treatment can be a fracturing operation. The fracturing operation can include introducing a fracturing fluid into the zone to be treated, wherein the fracturing fluid creates or enhances one or more fractures in the subterranean formation.

A zonal isolation device can include: a top slip; a top slip prop in engagement with the top slip; a bottom slip; a bottom slip prop in engagement with the bottom slip; an inner mandrel; and a sealing element positioned between the top slip prop and bottom slip prop and located circumferentially around the inner mandrel, wherein the sealing element comprises: an inner core; and an outer shell, wherein the outer shell surrounds the inner core, and wherein the outer shell is made from a material having a Young's modulus in the range of 500 to 300,000 megapascals (“MPa”) (0.5 to 300 gigapascals “GPa”).

Methods of isolating a zone of a subterranean formation can include introducing the zonal isolation device within a tubing string of a wellbore that penetrates the subterranean formation; and setting the isolation device at a desired location within the tubing string.

It is to be understood that the discussion of any of the embodiments regarding the plug is intended to apply to all of the method and apparatus embodiments without the need to repeat the various embodiments throughout. Any reference to the unit “gallons” means U.S. gallons.

Turning to the Figures, FIG. 1 shows an isolation device 100 in a run-in position according to any of the embodiments. As used herein, the terms “run into” and “run in” mean the isolation device plug is capable of being moved within a tubing string to a desired location and/or the time during which the isolation device is being introduced into a wellbore at a desired location. The isolation device 100 can be a plug. The plug can be used in an oil and gas operation. The oil or gas operation can be a fracturing operation or for zonal isolation. The isolation device 100 can be a frac plug, bridge plug, or zonal isolation plug. There can also be more than one isolation device 100 that is run into a tubing or casing string to provide zonal isolation.

As shown in FIG. 1, the isolation device 100 can include top slips 120, a top slip prop 122, a sealing element 130, a bottom slip prop 126, bottom slips 124, an inner mandrel 114 (shown in FIG. 2), and a mule shoe 140. The isolation device 100 can be a plug. The plug can be a frac plug. The components of the plug, excluding the sealing element, can be made from a variety of materials including, but not limited to, metals, metal alloys, molded hardened polymers, resins, or resin/glass composites. The components of the isolation device can have a variety of dimensions that are selected for the particular wellbore operation in which the isolation device is used.

The isolation device 100 can include a slip system located on the outside of the inner mandrel 114. As shown in the Figures, the inner mandrel 114 can extend from an area above the mule shoe 140, through the inner diameter of the device, and to an area above the top slips 120. The slip system includes the top slips 120 and the bottom slips 124. The slips 120/124 can be made from a single cylinder of material, a set of slips retained in a groove on the slip prop, or a single cylinder of material containing a plurality of slots or grooves. The slips 120/124 can be located around a portion of the outside of the inner mandrel 114 and radially biased towards the outside of the inner mandrel 114. The slips 120/124 can have buttons or teeth 127 on its face. As used herein, the terms “button” and “teeth” include one or more elements that are capable of grippingly engaging an inner diameter (I.D.) 161 of a tubing string or casing 160 to retain the isolation device 100 in a set position as shown in FIG. 3. The buttons or teeth 127 can include sharp ridges machined onto the face of the slips 120/124 or sharp elements, for example, rounded or other geometric shapes that are attached to the face of the slips 120/124. The slip system can further include slip props.

As shown in FIGS. 1-3, an upper and a lower end of each of the slips 120/124 can be formed having a conical or ramped surface. The surfaces of the slips 120/124 allow a parallel, angled surface 122a of a top slip prop 122 and a parallel, angled surface 126a of a bottom slip prop 126 to slidingly engage with the ramped surfaces of the slips 120/124. In one position, the slips 120/124 can be positioned substantially adjacent to the inner mandrel 114 and axially separated from the top slip prop 122 and bottom slip prop 126 so that the outer diameter (O.D.) of the slips 120/124 is less than or equal to the O.D. of the slip props 122/126. As used herein, the term “slip prop” includes a wedge, cone, or any device that can support the slips 120/124 when the isolation device 100 is set.

After the isolation device 100 is run in the wellbore to a desired location, it can be set. FIG. 3 shows the isolation device 100 after setting. The isolation device 100 can be mechanically set using wireline or hydraulic setting tools and a setting sleeve 110, for example. The setting sleeve 110 can be attached to a setting tool (not shown).

Setting the isolation device 100 can involve applying compression to a slip system to move the slips 120/124 axially towards and along the face of the slip props 122/126 and radially away from the inner mandrel 114 and into engagement with the I.D. 161 of the tubing string or casing 160 and to allow the top slips 120 to maintain engagement with the tubing string or casing 160. The setting sleeve 110 can be mechanically actuated. The force applied to the device can increase the load on the slips 120/124 causing them to break via slots or grooves and ramp up the angled surfaces of the slip props 122/126 towards each other. Compression that is applied to the slip system causes the top slips 120 to move along the top slip prop 122, which in turn causes a lower end of the mule shoe 140 to move towards the top slips 120. Movement of the mule shoe 140 causes the bottom slips 126 to move along the bottom slip prop 126. The slip props 122/126 can support the slips 120/124 in an expanded position outward from the inner mandrel 114 such that the slips 120/124 engage the I.D. 161 of the tubing string or casing 160 when the isolation device 100 is set. The slip props 122/126 can prevent the slips 120/124 from retracting and releasing from the I.D. 161 of the tubing string once the isolation device 100 is set. When the slips 120/124 are engaged with the tubing string or casing 160, the isolation device 100 has substantially limited or no vertical movement within the wellbore.

The isolation device 100 also includes a sealing element 130. The sealing element 130 is positioned between the top slip prop 122 and the bottom slip prop 126 and located circumferentially around the inner mandrel 114. Setting the isolation device 100 can further involve causing the sealing element 130 to expand radially away from the inner mandrel 114 to form a pressure tight annular seal. The sealing element 130 can radially expand outwardly away from the inner mandrel 114 to engage with an inner diameter 161 of the tubing string or casing 160 when the isolation device 100 is set. Downward movement of the setting sleeve 110 and the upward movement of the mule shoe 140 causes the slip props 122/126 to move towards each other and axially compresses the sealing element 130 to cause it to expand into engagement with the I.D. 161 of the tubing string or casing 160. Engagement of the sealing element 130 with the inside of the tubing string or casing 160 can restrict fluid flow past the sealing element.

The sealing element 130 includes an inner core 132 and an outer shell 131. As can be seen in FIGS. 2-4, the outer shell 131 surrounds the inner core 132. As used herein, the term “shell” means a material that completely covers the outside of the inner core. The outer shell 131 has a thickness that is defined as the distance between the inside of the shell that is located next to the inner core and the outside of the shell that is not located directly next to the inner core.

The outer shell 131 can be made from a material that has a Young's modulus greater than 500 megapascals (MPa). The outer shell can be made from a material that has a Young's modulus in the range of 500 to 300,000 MPa (0.5 to 300 gigapascals “GPa”). Young's modulus E is a mechanical property that measures the tensile or compressive stiffness of a solid material when the force is applied lengthwise. It quantifies the relationship between tensile/compressive stress σ (force per unit area) and axial strain ε (proportional deformation) in the linear elastic region of a material and is determined using Eq. 1.

$\begin{array}{cc}E=\frac{\sigma }{\epsilon }& \mathrm{Eq}.1\end{array}$

Young's moduli are typically so large that they are expressed not in pascals but in megapascals (MPa) or gigapascals (GPa). When a material's length increases quickly when the force is applied, the Young's modulus will be very low. When a material's length increases slowly when the force is applied, the Young's modulus will be very high. Accordingly, a material with a low Young's modulus will be more elastic and less stiff compared to a material with a high Young's modulus.

The outer shell 131 can also have a bulk modulus greater than 500 MPa or in the range of 500 to 300,000 MPa (0.5 to 300 GPa). Bulk modulus (K) describes volumetric elasticity, or the tendency of an object to deform in all directions when uniformly loaded in all directions and defined as volumetric stress over volumetric strain. The bulk modulus is an extension of Young's modulus to three dimensions. A material's bulk modulus will oftentimes be very close to its Young's modulus.

As discussed above, a material with a low elastic modulus can be forced out away from the inner mandrel during run in by fluid within the tubing string, and thus, structural integrity of the sealing element during run in is not maintained. According to any of the embodiments, the Young's modulus of the material for the outer shell 131 is selected such that structural integrity of the sealing element 130 is maintained during run in and premature and undesirable deformation and extrusion of the sealing element 130 away from the inner mandrel 114 does not occur. Preventing the premature and undesirable deformation and extrusion of the sealing element also prevents premature setting of the isolation device 100 within the tubing string. According to any of the embodiments, the outer shell 131 is made from a material having a Young's modulus in the range of 20,000 to 120,000 MPa (20 to 120 GPa). Other properties of the outer shell, for example, yield strength or tensile strength can be selected such that the outer shell maintains structural integrity to the sealing element during run in.

The thickness of the outer shell 131 can be selected such that the outer shell maintains structural integrity to the sealing element 130 during run in. By way of example, for a material that has a Young's modulus of 45 GPa (45,000 MPa) (e.g., pure magnesium), then the thickness of the outer shell 131 can be greater than the thickness of the shell made from aluminum having a Young's modulus of 60 GPa (65,000 MPa). Accordingly, the thickness of the outer shell 131 may be inversely related to the Young's modulus of the material. The thickness of the outer shell 131 can also be selected based on the Young's modulus of the material and the amount of force that is anticipated to be encountered during run in. In this manner, the outer shell 131 still functions to maintain structural integrity of the sealing element 130 during run in. The thickness of the outer shell 131 can be in the range of 0.01 inches to 1 inch.

Materials for the outer shell having the desired Young's modulus include, but are not limited to, metals, metal alloys, and composites. As used herein, the term “metal alloy” means a mixture of two or more elements, wherein at least one of the elements is a metal. The other element(s) can be a non-metal or a different metal. An example of a metal and non-metal alloy is steel, comprising the metal element iron and the non-metal element carbon. An example of a metal and metal alloy is bronze, comprising the metallic elements copper and tin. It is to be understood that use of the term “metal” is meant to include pure metals and metal alloys. Examples of suitable pure metals and metals for metal alloys include, but are not limited to, magnesium, aluminum, tin, zinc, copper, beryllium, barium, or manganese. Preferred metal alloys include alloys of magnesium-zinc, magnesium-aluminum, copper-zinc, or aluminum-copper. The non-metal elements of the metal alloy can include, but are not limited to, graphite, carbon, silicon, and boron nitride. Examples of suitable composites include, but are not limited to, epoxy-based composites or structural molded phenolics. The epoxy-based composites can be, for example, a glass fiber-reinforced epoxy composite or a carbon fiber-reinforced epoxy composite. The structural molded phenolic can be, for example, thermoplastics or thermoset composite materials.

Unlike packers that are generally intended to be permanent or retrievable, other wellbore isolation devices are designed to limit or eliminate the need for post treatment operations after use. Having a sealing element that disintegrates allows for limited or no intervention to remove the device after use. According to any of the embodiments, the material for the outer shell 131 disintegrates. As used herein, the term “disintegrate” and all grammatical variations thereof means to lose intactness or solidness; break up; deteriorate. Disintegration can occur from degradation, dissolution, corrosion (including galvanic corrosion), or melting. A degradable material can be chemically broken down, for example, by a wellbore or subterranean formation fluid. Dissolvable materials can dissolve in a solvent and corrosive materials can corrode in a fluid (e.g., an electrolyte solution). According to any of the embodiments, the thickness of the outer shell 131 is selected such that at least a portion of the outer shell 131 disintegrates in a desired amount of time after setting. By way of example, a desired amount of time after setting can be in the range of 4 to 24 hours. Accordingly, the material for the outer shell 131 and the thickness can be selected such that at least a portion of the outer shell 131 disintegrates in the desired amount of time after setting.

The sealing element 130 also includes the inner core 132. The inner core 132 provides the main structural support for the outer shell 131. The inner core 132 can have desired dimensions and geometries selected based on the specifics of the isolation device 100, such as the top and bottom slip props 122/126 and the outer diameter of the inner mandrel 114. The inner core 132 can be made from a material that is different from the outer shell 131. According to any of the embodiments, the inner core 132 is made from a material having a Young's modulus less than the Young's modulus of the material making up the outer shell 131. In this manner, the inner core 132 has a more elastic property than the outer shell 131. By way of example, the inner core 132 can be made from a material having a Young's modulus of 5 MPa. According to any of the embodiments, the inner core 132 is made from a material having a Young's modulus less than 50 MPa. The material for the inner core 132 can also be compressible. In this manner, the sealing element 130 is capable of expanding radially outward from the inner mandrel 114 during setting of the isolation device 100 and engages with the I.D. 161 of the tubing string or casing 160.

The inner core 132 can be made of a solid material that disintegrates or can be made of a fluid. Examples of suitable solid materials for the inner core 132 include, but are not limited to, elastomeric materials, for example, polyurethane rubbers, natural or synthetic polymers, or nitrile butadiene rubbers. The inner core 132 can also be a fluid. The fluid can be a gel, semi-gel, or liquid. The inner core 132 can disintegrate after exposure to wellbore fluids. The exposure can occur after at least a portion of the outer shell 131 disintegrates at the desired time after setting the isolation device 100 in the tubing or casing string 160. As discussed above regarding problems with other plugs, is that in order to control the disintegration rate of sealing elements, additives are typically included in the sealing element—such additives oftentimes negatively effecting the elasticity or hardness of the sealing element. Because the inner core 132 is not exposed to fluids that can cause disintegration due to the outer shell 131, then the rate of disintegration of the inner core 132 may not have to be altered. Accordingly, the inner core 132 can advantageously be made of a material that disintegrates very rapidly once exposed to wellbore fluids. Moreover, by not needing to include additives to alter the disintegration rate, the properties of the inner core 132 are not adversely affected and can be more desirable.

A method of manufacturing the sealing element can include an extrusion process in which the outer shell is formed as a single piece having a generally toroid shape. The outer shell can be formed to include one or more openings, or one or more openings can be made after the extrusion process. The inner core can then be injected into the outer shell via the one or more openings. The material making up the inner core may need to be heated to a temperature above its melting point to be capable of injecting the inner core material into the outer shell. If the material making up the inner core has to be heated, then after injection into the outer shell, the material can be allowed to cool down to a temperature less than the melting point. The one or more openings can be sealed after injection of the inner core. Alternatively, the outer shell can be manufactured as two separate pieces. The material for the inner core can then be placed within each half of the outer shell and the two pieces then conjoined. The two pieces can also be conjoined first and then the material for the inner shell can be placed within the outer shell.

The methods include introducing the zonal isolation device within a tubing string of a wellbore that penetrates the subterranean formation and setting the isolation device at a desired location within the tubing string. The isolation device 100 can be run into the tubing string or casing string via a wireline, for example. During run in the outer shell prevents premature deformation or expansion of the sealing element and premature setting of the isolation device. After the isolation device has reached the desired location within the tubing string, then the slip system can be engaged to cause the top and bottom slips to engage with the I.D. of the tubing string. The slip system can also cause the sealing element to become axially compressed at both ends and force the sealing element to radially expand outwardly away from the inner mandrel to engage with the I.D. of the tubing string to create a seal.

According to any of the embodiments, the material of the outer shell is expandable and deformable such that during compression, the outer shell remains intact and completely surrounds the inner core. In this manner, the inner core is not yet exposed to wellbore fluids that cause disintegration of the inner core. Accordingly, at least a portion of the outer shell can disintegrate at a desired time after setting or the outer shell can be punctured to expose the inner core to wellbore fluids and begin disintegrating.

According to certain other embodiments, not all of the outer shell remains intact and completely surrounds the inner core. According to these embodiments, cracks in the outer shell can form during compression of the sealing element during setting. According to these embodiments, the outer shell may be made from a material that does not disintegrate because the inner core is exposed to wellbore fluids via the cracks in the outer shell. Accordingly, the inner core is exposed to wellbore fluids during and after setting. The inner core may need to include additives that delay disintegration of the inner core. The material for the inner core may also be selected such that the wellbore fluids at the time of exposure do not cause the inner core to disintegrate. Another fluid that does cause disintegration to the inner core can be introduced after the isolation device is no longer needed for the wellbore operation.

The methods can further include fracturing a portion of a subterranean formation that is penetrated by the wellbore. The step of fracturing can include introducing a fracturing fluid into a zone of the formation, wherein the fracturing fluid creates or enhances a fracture in the formation. The methods can further include removing the isolation device from the tubing string after use. By way of example, after a fracturing operation has been performed, the isolation device may no longer be needed. The sealing element can be designed wherein a sufficient amount of the sealing element disintegrates such that the isolation device can be removed from the tubing string. The isolation device or components of the isolation device can also be drilled or milled out of the tubing string.

An embodiment of the present disclosure is a zonal isolation device comprising: a top slip; a top slip prop in engagement with the top slip; a bottom slip; a bottom slip prop in engagement with the bottom slip; an inner mandrel; and a sealing element positioned between the top slip prop and bottom slip prop and located circumferentially around the inner mandrel, wherein the sealing element comprises: an inner core; and an outer shell, wherein the outer shell surrounds the inner core, and wherein the outer shell is made from a material having a Young's modulus in the range of 500 to 300,000 megapascals. Optionally, the device further comprises wherein the isolation device is a frac plug, bridge plug, or zonal isolation plug. Optionally, the device further comprises wherein the outer shell has a bulk modulus in the range of 500 to 300,000 megapascals. Optionally, the device further comprises wherein the material of the outer shell has a Young's modulus selected such that structural integrity of the sealing element is maintained during run in. Optionally, the device further comprises wherein the outer shell is made from a material having a Young's modulus in the range of 20,000 to 120,000 MPa. Optionally, the device further comprises wherein the outer shell has a thickness, and wherein the thickness is in the range of 0.01 inches to 1 inch. Optionally, the device further comprises wherein the material of the outer shell is selected from pure metals, metal alloys, or composites. Optionally, the device further comprises wherein the pure metal or metal of the metal alloy is selected from the group consisting of magnesium, aluminum, tin, zinc, copper, beryllium, barium, manganese, and combinations thereof. Optionally, the device further comprises wherein the composite is an epoxy-based composite or structural molded phenolics. Optionally, the device further comprises wherein the epoxy-based composite is a glass fiber-reinforced epoxy composite or a carbon fiber-reinforced epoxy composite. Optionally, the device further comprises wherein at least a portion of the outer shell and the inner core are configured to disintegrate in a desired amount of time after the device is set within a tubing string. Optionally, the device further comprises wherein the disintegration occurs via degradation, dissolution, melting, or corrosion. Optionally, the device further comprises wherein the inner core is made from a material having a Young's modulus less than the Young's modulus of the material of the outer shell. Optionally, the device further comprises wherein the inner core is made from a material having a Young's modulus less than 50 megapascals. Optionally, the device further comprises wherein the material for the inner core is an elastomeric material, and wherein the elastomeric material is a polyurethane rubber or nitrile butadiene rubber. Optionally, the device further comprises wherein the inner core is a fluid, and wherein the fluid is a gel, semi-gel, or liquid.

Another embodiment of the present disclosure is a method of isolating a zone of a subterranean formation comprising: (I) introducing a zonal isolation device within a tubing string of a wellbore that penetrates the subterranean formation, wherein the zonal isolation device comprises: (A) a top slip; (B) a top slip prop in engagement with the top slip; (C) a bottom slip; (D) a bottom slip prop in engagement with the bottom slip; (E) an inner mandrel; and (F) a sealing element positioned between the top slip prop and bottom slip prop and located circumferentially around the inner mandrel, wherein the sealing element comprises: (i) an inner core; and (ii) an outer shell, wherein the outer shell surrounds the inner core, and wherein the outer shell is made from a material having a Young's modulus in the range of 500 to 300,000 megapascals; and (II) setting the isolation device at a desired location within the tubing string. Optionally, the method further comprises wherein setting the isolation device comprises causing the sealing element to expand radially away from the inner mandrel to form a pressure tight annular seal. Optionally, the method further comprises wherein the outer shell has a thickness, and wherein the thickness of the outer shell is selected such that the outer shell maintains structural integrity to the sealing element during the step of introducing the zonal isolation device within the tubing string. Optionally, the method further comprises wherein the isolation device is a frac plug, bridge plug, or zonal isolation plug. Optionally, the method further comprises wherein the outer shell has a bulk modulus in the range of 500 to 300,000 megapascals. Optionally, the method further comprises wherein the material of the outer shell has a Young's modulus selected such that structural integrity of the sealing element is maintained during run in. Optionally, the method further comprises wherein the outer shell is made from a material having a Young's modulus in the range of 20,000 to 120,000 MPa. Optionally, the method further comprises wherein the outer shell has a thickness, and wherein the thickness is in the range of 0.01 inches to 1 inch. Optionally, the method further comprises wherein the material of the outer shell is selected from pure metals, metal alloys, or composites. Optionally, the method further comprises wherein the pure metal or metal of the metal alloy is selected from the group consisting of magnesium, aluminum, tin, zinc, copper, beryllium, barium, manganese, and combinations thereof. Optionally, the method further comprises wherein the composite is an epoxy-based composite or structural molded phenolics. Optionally, the method further comprises wherein the epoxy-based composite is a glass fiber-reinforced epoxy composite or a carbon fiber-reinforced epoxy composite. Optionally, the method further comprises wherein at least a portion of the outer shell and the inner core are configured to disintegrate in a desired amount of time after the device is set within a tubing string. Optionally, the method further comprises wherein the disintegration occurs via degradation, dissolution, melting, or corrosion. Optionally, the method further comprises wherein the inner core is made from a material having a Young's modulus less than the Young's modulus of the material of the outer shell. Optionally, the method further comprises wherein the inner core is made from a material having a Young's modulus less than 50 megapascals. Optionally, the method further comprises wherein the material for the inner core is an elastomeric material, and wherein the elastomeric material is a polyurethane rubber or nitrile butadiene rubber. Optionally, the method further comprises wherein the inner core is a fluid, and wherein the fluid is a gel, semi-gel, or liquid.

Therefore, the various embodiments are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the various embodiments may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention.

As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. While compositions, systems, and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions, systems, and methods also can “consist essentially of” or “consist of” the various components and steps. It should also be understood that, as used herein, “first,” “second,” and “third,” are assigned arbitrarily and are merely intended to differentiate between two or more slip props, slips, etc., as the case may be, and does not indicate any sequence. Furthermore, it is to be understood that the mere use of the word “first” does not require that there be any “second,” and the mere use of the word “second” does not require that there be any “third,” etc.

Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

Claims

1. A zonal isolation device comprising:

a top slip;

a top slip prop in engagement with the top slip;

a bottom slip;

a bottom slip prop in engagement with the bottom slip;

an inner mandrel; and

a sealing element positioned between the top slip prop and bottom slip prop and located circumferentially around the inner mandrel, wherein the sealing element comprises: an inner core, wherein the inner core is made from a material having a Young's modulus less than 50 megapascals; and an outer shell, wherein the outer shell surrounds the inner core, and wherein the outer shell is made from a material having a Young's modulus in the range of 500 to 300,000 megapascals,

wherein mechanical actuation of the sealing element causes the sealing element to create a seal against an inside of a casing string or tubing string.

2. The device according to claim 1, wherein the isolation device is a frac plug, bridge plug, or zonal isolation plug.

3. The device according to claim 1, wherein the outer shell has a bulk modulus in the range of 500 to 300,000 megapascals.

4. The device according to claim 1, wherein the material of the outer shell has a Young's modulus selected such that structural integrity of the sealing element is maintained during run in.

5. The device according to claim 1, wherein the outer shell is made from a material having a Young's modulus in the range of 20,000 to 120,000 MPa.

6. The device according to claim 1, wherein the outer shell has a thickness, and wherein the thickness is in the range of 0.01 inches to 1 inch.

7. The device according to claim 1, wherein the material of the outer shell is selected from pure metals, metal alloys, or composites.

8. The device according to claim 7, wherein the pure metal or metal of the metal alloy is selected from the group consisting of magnesium, aluminum, tin, zinc, copper, beryllium, barium, manganese, and combinations thereof.

9. The device according to claim 7, wherein the composite is an epoxy-based composite or structural molded phenolics.

10. The device according to claim 9, wherein the epoxy-based composite is a glass fiber-reinforced epoxy composite or a carbon fiber-reinforced epoxy composite.

11. The device according to claim 1, wherein at least a portion of the outer shell and the inner core are configured to disintegrate in a desired amount of time after the device is set within a tubing string.

12. The device according to claim 11, wherein the disintegration occurs via degradation, dissolution, melting, or corrosion.

13. The device according to claim 1, wherein the inner core is made from a material having a Young's modulus less than the Young's modulus of the material of the outer shell.

14. (canceled)

15. The device according to claim 1, wherein the material for the inner core is an elastomeric material, and wherein the elastomeric material is a polyurethane rubber or nitrile butadiene rubber.

16. The device according to claim 1, wherein the inner core is a fluid, and wherein the fluid is a gel, semi-gel, or liquid.

17. A method of isolating a zone of a subterranean formation comprising:

(I) introducing a zonal isolation device within a tubing string of a wellbore that penetrates the subterranean formation, wherein the zonal isolation device comprises: (A) a top slip; (B) a top slip prop in engagement with the top slip; (C) a bottom slip; (D) a bottom slip prop in engagement with the bottom slip; (E) an inner mandrel; and (F) a sealing element positioned between the top slip prop and bottom slip prop and located circumferentially around the inner mandrel, wherein the sealing element comprises: (i) an inner core, wherein the inner core is made from a material having a Young's modulus less than 50 megapascals; and (ii) an outer shell, wherein the outer shell surrounds the inner core, and wherein the outer shell is made from a material having a Young's modulus in the range of 500 to 300,000 megapascals; and

(II) setting the isolation device at a desired location within the tubing string, wherein setting comprises mechanical actuation of the sealing element that causes the sealing element to create a seal against an inside of the tubing string.

18. The method according to claim 17, wherein setting the isolation device comprises causing the sealing element to expand radially away from the inner mandrel to form a pressure tight annular seal.

19. The method according to claim 17, wherein the outer shell has a thickness, and wherein the thickness of the outer shell is selected such that the outer shell maintains structural integrity to the sealing element during the step of introducing the zonal isolation device within the tubing string.

20. The method according to claim 17, wherein at least a portion of the outer shell and the inner core are configured to disintegrate in a desired amount of time after the device is set within the tubing string.

21. The method according to claim 17, wherein the material of the outer shell has a Young's modulus selected such that structural integrity of the sealing element is maintained during run in.